System and method for producing, dispensing, using and monitoring a hydrogen enriched fuel

ABSTRACT

A system for producing, dispensing, using and monitoring a hydrogen enriched fuel includes a producing system configured to produce the hydrogen enriched fuel, a vehicle having an engine configured to use the hydrogen enriched fuel, and a dispensing system configured to store and dispense the hydrogen enriched fuel into the vehicle. The system also includes a fuel delivery system on the vehicle configured to deliver the hydrogen enriched fuel to the engine, and a control system configured to control the producing system and to monitor the use of the hydrogen enriched fuel by the vehicle. A method includes the steps of producing hydrogen gas and a hydrocarbon fuel, blending the hydrogen gas and the hydrocarbon fuel into the hydrogen enriched fuel, using the hydrogen enriched fuel in the engine, and tracking emissions during the producing step and during the using step.

FIELD OF THE INVENTION

This invention relates generally to alternative fuels, and particularlyto a system and a method for producing, dispensing, using and monitoringa hydrogen enriched fuel.

BACKGROUND OF THE INVENTION

Gaseous alternative fuels, such as hydrogen and natural gas, are valuedfor their clean burning characteristics in motor vehicle engines. Aparticularly clean burning gaseous alternative fuel known as HYTHANE isformed from a mixture of hydrogen and natural gas. The prefix “Hy” inHYTHANE is taken from hydrogen. The suffix “thane” in HYTHANE is takenfrom methane, which is the primary constituent of natural gas. HYTHANEis a registered trademark of Brehon Energy PLC. HYTEANE typicallycontains about 5% to 7% hydrogen by energy. Natural gas is typicallyabout 90+% methane, along with small amounts of ethane, propane, higherhydrocarbons, and “inerts” like carbon dioxide or nitrogen.

Hydrogen and methane are complimentary vehicle fuels in many ways.Methane has a relatively narrow flammability range that limits the fuelefficiency in engine applications utilizing a dilute air/fuel mixtureand super-aspiration. It is common to dilute the air/fuel mixture witheither excess air or recycled exhaust gases, known as lean-burn andexhaust gas recirculation (EGR), respectively. Super-aspiration iscommonly achieved with a turbocharger or other supercharging pump. Theaddition of even a small amount of hydrogen extends the leanflammability range significantly. Methane also has a slow flame speed,especially in lean air/fuel mixtures, while hydrogen has a flame speedabout 8 times faster. Methane is a fairly stable molecule that can bedifficult to ignite, but hydrogen has an ignition energy requirementabout 25 times lower than methane. Finally, methane can be difficult tocompletely combust in the engine or catalyze in exhaust aftertreatmentconverters. In contrast, hydrogen is a powerful combustion stimulant foraccelerating the methane combustion within an engine, and hydrogen isalso a powerful reducing agent for efficient catalysis at lower exhausttemperatures.

Although pure hydrogen fuel can reduce emissions by up to 100%, in thenear term there is an objectionable cost differential between fossilfuels and hydrogen. Hydrogen costs are proportional to hydrogen energy,which may be expressed as a percentage of the energy consumed by thebaseline energy system (e.g., a non-hydrogen fueled vehicle). However,hydrogen costs alone do not consider the benefits provided by a hydrogenfuel system. To fully understand the benefits of using hydrogen as afuel, a larger view of the use and economics of hydrogen is necessary.

The present invention considers the reduction in emissions by a hydrogenenriched fuel. The ratio of percent emissions reduction to percenthydrogen energy, relative to baseline conditions, is a measure of theeffectiveness of hydrogen utilization called the leverage factor.Hydrogen leverage is defined as the ratio of [% Emissions Reduction]/[%Baseline Energy Supplied as Hydrogen]. For example, a fleet of 100natural gas buses converted for operation on pure hydrogen, will have atotal reduction in emission of about 7%. This means the leverage ofusing hydrogen is 7%/7%=1. However, the same fleet could use the sameamount of hydrogen (7% by energy), blended with natural gas for all 100buses, and achieve an emissions reduction of 50% for the entire fleet.In this case, the hydrogen leverage is 50%/7%=7.14, or over 7 times aseffective as the pure hydrogen case.

The present invention also considers the complete life cycle of thefuel. For example, a biofuel such as ethanol may reduce the emissionsproduced by a gasoline engine. However, production of the ethanol mayinclude diesel fuel burned in the farm tractors, burning of theagricultural waste, production of excess carbon dioxide duringfermentation and distillation, and more diesel burned in tanker trucksfor distribution. The present invention recognizes that all of theseemission sources must be considered before any valid comparison can bemade between the ethanol fuel and the baseline fuel it is replacing.

Despite persistent interest and significant progress in using hydrogenas a vehicle fuel, it has not yet become an established alternativefuel, like alcohols, propane or natural gas. The present invention isdirected to a system that utilizes a “wells to wheels” approach, forproducing, dispensing, using and monitoring a hydrogen enriched fuel.With the system of the invention, a life cycle assessment can comparethe total environmental impact associated with the production,transportation and use of the hydrogen enriched fuel, relative to anyother baseline fuel.

The foregoing examples of the related art and limitations relatedtherewith are intended to be illustrative and not exclusive. Otherlimitations of the related art will become apparent to those of skill inthe art upon a reading of the specification and a study of the drawings.

SUMMARY OF THE INVENTION

A system and a method for producing, dispensing, using and monitoring ahydrogen enriched fuel are provided. The following embodiments andaspects thereof are described and illustrated in conjunction with asystem and method, which are meant to be exemplary and illustrative, notlimiting in scope.

The system includes at least one vehicle having an engine configured touse the hydrogen enriched fuel. The system also includes a producingsystem configured to produce the hydrogen enriched fuel, and adispensing system configured to dispense the hydrogen enriched fuel intothe vehicle. The system also includes a control system configured tomonitor emissions and energy consumption by the vehicle during use ofthe hydrogen enriched fuel. In addition, the control system isconfigured to monitor and control the production of the hydrogenenriched fuel, and to gather the necessary data for emissions and energyconsumption tracking. The control system can also be used to minimizeemissions during production and use of the hydrogen enriched fuel, andto minimize energy consumption relative to a baseline fuel.

The producing system includes a hydrogen source configured to provide ahydrogen gas, and a hydrocarbon source configured to provide a basehydrocarbon fuel. The hydrogen gas and the hydrocarbon fuel can becooled, mixed and compressed by the producing system to provide thehydrogen enriched fuel as a pre-blended pressurized gas or fluid, in acryogenic, or a supercritical state. Alternately, the producing systemcan provide the hydrogen gas and the hydrocarbon fuel to the vehicle asseparate elements, which can then be mixed on board the vehicle.

The dispensing system, and components of the producing system and thecontrol system as well, can be located at a refueling station similar instructure and function to a conventional gas station. In an illustrativeembodiment, the dispensing system is configured to dispense the hydrogenenriched fuel to the vehicle in the pre-blended condition. In analternate embodiment, the hydrogen gas and the hydrocarbon fuel areprovided as separate elements, and the vehicle includes a constantvolume injecting system for blending the hydrogen gas and thehydrocarbon fuel.

The method includes the steps of providing a hydrogen enriched fuel,dispensing the hydrogen enriched fuel into the vehicle, using thehydrogen enriched fuel in the vehicle engine, and monitoring emissionsand fuel consumption at least during the using step. The monitoring stepcan sense and record engine performance data, such as engine operatingconditions, exhaust emission data, and mileage data. The monitoring stepcan also monitor data to estimate and track the emissions over theentire life cycle of the hydrogen enriched fuel including duringproducing, dispensing and using of the hydrogen enriched fuel. Inaddition, the monitoring step can certify the condition of the hydrogenenriched fuel and provide safety and control during producing,dispensing and using of the hydrogen enriched fuel.

BRIEF DESCRIPTION OF THE DRAWINGS

Exemplary embodiments are illustrated in the referenced figures of thedrawings. It is intended that the embodiments and the figures disclosedherein are to be considered illustrative rather than limiting.

FIG. 1 is a schematic drawing of a system for producing, dispensing,using and monitoring a hydrogen enriched fuel;

FIG. 2 is a schematic diagram showing a blending system, a compressingsystem, a storage system and a dispensing system of the system;

FIG. 2A is an enlarged view of FIG. 2 taken along line 2A;

FIG. 2B is an enlarged view of FIG. 2 taken along line 2B;

FIG. 2C is an enlarged view of FIG. 2 taken along line 2C;

FIG. 2D is an enlarged view of FIG. 2 taken along line 2D;

FIG. 3 is a schematic diagram of a master control system of the system;

FIG. 4 is a schematic drawing of a dispensing system of the system;

FIG. 5 is a cross sectional view of a system for blending hydrogen gasand a hydrocarbon fuel on board a vehicle engine; and

FIG. 6 is a graph showing the effect of various hydrogen concentrationson NOx emissions from a modified Cummins L-10 bus engine in a steadystate simulation of the Federal emissions test.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following definitions are used in the present disclosure.

HYTHANE means a hydrogen enriched fuel which includes hydrogen andmethane (natural gas).

Supercritical cryogenic fuel (SCCF) means a hydrogen enriched fuel whichincludes hydrogen gas dissolved in a supercritical hydrocarbon fluid.

Supercritical fluid means a fluid at a pressure and temperature whichare above the critical temperature and pressure of the fluid. In thisstate, there is no differentiation between the liquid and gas phases,and the fluid is referred to as a dense gas in which the saturated vaporand saturated liquid states are identical.

Greenhouse emissions mean emissions to the atmosphere which contributeto the greenhouse effect and global warming.

System 10

Referring to FIG. 1, a system 10 for producing, dispensing, using andmonitoring a hydrogen enriched fuel are illustrated. The system 10includes a producing system 12 for producing the hydrogen enriched fuel,a dispensing system 14 for dispensing the hydrogen enriched fuel, and avehicle 16 having an engine 18 configured to use the hydrogen enrichedfuel. The vehicle also includes a fuel delivery system 20 for the engine18 and an engine control module 46.

The system 10 (FIG. 1) also includes a master control system 44 insignal communication via communication lines 182 with the engine controlmodule 46 on the vehicle 16, with an audit and control module 88 of thedispensing system 14, and with components of the producing system 12.The master control system 44 is configured to sense, retrieve, store andcommunicate vehicle specific data, particularly exhaust emission data(or operating data which can be used to estimate emissions) and vehiclemileage data. This data can be used to adjust or re-configure particularvehicles 16 for reducing emissions and reducing energy consumption. Thisdata can also be used to provide an accounting of the reduction ofglobal warming gases for the carbon credit system of the 1997 KyotoProtocol. Rather than just vehicle emissions, the master control system44 can also be used to monitor emissions over the entire life cycle ofthe hydrogen enriched fuel including emissions produced by components ofthe producing system 12. The master control system 44 can also beconfigured to monitor and certify the condition of the hydrogen enrichedfuel produced by the producing system 12, and to provide safety andcontrol for the producing system 12, the dispensing system 14 and thevehicle 16.

In the illustrative embodiment, the hydrogen enriched fuel comprisesHYTHANE, which includes hydrogen gas blended in a methane fuel. Inaddition, the methane fuel can be in the form of a compressed gas (CNG),a liquid natural gas (LNG) or a supercritical fluid. However, ratherthan a methane fuel, the hydrogen enriched fuel can include otherhydrocarbon fuels, such as ethylene, ethane, propane, propylene,propene, and butane. As another alternative, the hydrogen enriched fuelcan include multiple hydrocarbons, such as methane combined with higherhydrocarbons such as ethylene, ethane, propane, propylene, propene, andbutane. Further, the hydrogen enriched fuel can include additivesconfigured to improve physical or performance characteristics.

Producing System 12

As shown in FIG. 1, the producing system 12 includes a hydrogen source22 and a methane (natural gas) source 24. The producing system 12 alsoincludes a blending system 26 for blending the hydrogen and the methane(natural gas) into HYTHANE at a common temperature. A representativerange for the temperature can be from 40° C. to 125° C. The blendingsystem 26 also includes a compressor system 28 for compressing theHYTHANE to a selected pressure. A representative range for the selectedpressure can be from 2000 psig to 5000 psig for useful vehicle storage.

The blending system 26 (FIG. 1) can be located at a refueling station 34(FIG. 1) similar in structure and function to a conventional gas servicestation. Alternately, the blending system 26 (FIG. 1) can be located atanother location, and the pre-blended HYTHANE transported to therefueling station 34 (FIG. 1). The producing system 12 (FIG. 1) alsoincludes a fuel transportation system 32 (FIG. 1) for transportinghydrogen from the hydrogen source 22, and methane from the methane(natural gas) source 24 to the blending system 26. The producing system12 (FIG. 1) also includes a storage system 30 (FIG. 1) in the form of acascade of storage tanks located at the refueling station 34 (FIG. 1).At least the final stage of the cascade is kept at a significantlyhigher pressure than the maximum pressure of the vehicle fuel tank 42(FIG. 1), in order to dispense fuel quickly from the dispensing system14 (FIG. 1) into the vehicle fuel tank 42 (FIG. 1). Without highpressure storage, only slow-fill dispensing is possible, which is notpractical for large fleets of high-utilization vehicles.

Hydrogen Source 22

The hydrogen source 22 (FIG. 1) is selected and operated to minimizeemissions and energy consumption during hydrogen production. There aremany possible hydrogen sources, and the choice can have a large effecton the overall environmental impact of the system 10 (FIG. 1). Suitablehydrogen sources include electrolysis, exotic water splitting,industrial waste streams, wells, reforming, and gasification.

Electrolysis—Hydrogen Source 22

Electrolysis is a process for splitting the water molecule into itsconstituent hydrogen and oxygen using electrical power input.Electrolysis of water may use electricity from renewable energy likewind power or solar photovoltaic cells or from the common electricalenergy grid.

While electrolysis can be convenient for producing hydrogen in anylocation where water and electricity are available, the equipment can beexpensive. In addition, the cost of the hydrogen produced byelectrolysis is usually more expensive than other sources, depending onthe cost of the electrical input power. One feature makes electrolysisspecial when compared to other hydrogen production methods: it ispossible to electrolyze water at high pressures, and the over-voltagerequired to produce pressurized hydrogen is almost thermodynamicallyperfect. From an efficiency standpoint, high-pressure electrolysis isperhaps the best way to produce pressurized hydrogen. Since electrolysisuses relatively expensive electrical power and equipment, ‘highefficiency’ doesn't always mean ‘low cost,’ however.

Exotic Water Splitting—Hydrogen Source 22

More exotic methods for splitting water have been demonstrated, but arenot in common use at the moment. These methods include nuclearthermo-chemical, photolytic, and microbial or electrically assistedmicrobial processes.

Industrial Waste Stream—Hydrogen Source 22

From an environmental point of view, the next best thing to the hydrogenproduced by certain renewable electrolysis processes would be theutilization of an industrial waste stream with significant hydrogencontent. Industrial waste can also be the lowest-cost source of hydrogenin many cases. Steel and secondary aluminum production,chlorine/alkaline plants, glass factories, paper mills, and sometimesoil or gas refineries produce hydrogen-rich waste gas streams. There aremany proven industrial techniques for separating hydrogen, which arefacilitated by the many characteristics of hydrogen that make it uniqueamong other gases.

HYTHANE is not particularly sensitive to the final purity of thehydrogen source. Parts-per-million levels of contaminants typicallyfound in hydrogen waste streams, like carbon monoxide, for instance, canpermanently damage fuel cells. However, an engine fuelled by HYTHANEwill not be significantly affected by carbon monoxide mixed with thehydrogen and natural gas up to several percent. In fact, carbon monoxidehas a wide flammability range similar to hydrogen, and thecharacteristic combustion delay of carbon monoxide is accelerated by thepresence and combustion of hydrogen. Other gases that do not permanentlycontaminate and damage a fuel cell can still impair performance whilepresent in the hydrogen supply stream, like nitrogen, carbon dioxide,methane, etc. Most of these constituents are common in the various gasesfound in natural gas, so again, a HYTHANE engine is very robust when itcomes to fuel quality. In addition, there is a huge capital and energycost difference between hydrogen separation equipment that produces 90+%hydrogen for HYTHANE versus equipment that produces the 99.9999+% puritynecessary for fuel cells.

Wells (Natural Deposits)—Hydrogen Source 22

Although it is not common, there are certain natural gas deposits with arelatively high concentration of hydrogen occurring naturally. While toomuch hydrogen can be a problem for typical heating equipment set up forpipeline natural gas supply, the hydrogen removed from these sources canbe used further downstream for vehicle refueling. If a naturalhydrogen-rich gas deposit happens to be at the right location, it mayeven be possible to use dedicated pipelines from the well and fuelconditioning plant to HYTHANE vehicle refueling stations.

Reforming and Gasification—Hydrogen Source 22

The majority of the commercial hydrogen available today is made from thehigh temperature chemical reaction of natural gas and water, calledsteam reformation. This process produces carbon dioxide and consumessome of the fuel energy of the original natural gas feedstock. So, froma life cycle perspective, this is not the best choice of hydrogen forenergy efficiency or greenhouse gas emissions. However, steam reformednatural gas is generally the lowest-cost source of hydrogen, and theprocess is scaleable from huge oil refinery size plants down to on-siteunits for HYTHANE dispensing systems. Only a natural gas source andwater (and a small amount of electrical power for control) are needed toproduce relatively low-cost hydrogen at new or existing natural gasrefueling facilities where other sources of hydrogen may be tooexpensive or are otherwise unavailable.

Hydrogen is also produced by the partial oxidation of variousfeedstocks, including biomass or coal, a process generally referred toas gasification. The product stream from the partial oxidation stepincludes hydrogen and carbon monoxide, along with water vapor, carbondioxide, and nitrogen. The heat produced by the partial oxidation can beused with additional steam injection to create more hydrogen and carbondioxide from the endothermic reaction of water and carbon monoxide (theautothermal water gas shift process).

Methane (Natural Gas) Source 24

Like the hydrogen source 22, the choice of the methane (natural gas)source 24 for HYTHANE can have a significant impact on the life cycleassessment of the system emissions. As with the hydrogen source 22 themethane (natural gas) source 24 is selected and operated to minimizeemissions and energy consumption. Suitable methane (natural gas) sources24 include wells, industrial waste streams, and biogas.

Wells (Natural Deposits)—Methane (Natural Gas) Source 24

Almost all of the methane in the world's energy networks comes fromnatural “fossil fuel” deposits. These sources are the most widespreadand provide the least expensive methane for industrial or vehicular use.This source also takes a sequestered form of carbon and eventually putsit back into the atmosphere as greenhouse gas, so the environmentalimpact of this source must be considered. Life cycle emissions of fossilnatural gas can still compare favorably against other fuels with moreenergy-intense production processes or higher carbon concentrations,like gasoline for instance.

In the future, huge ocean deposits of icy natural gas hydrate (NGH)compounds may provide a significant source of methane. The total methaneenergy contained within and under these hydrate formations is estimatedto be at least double the known underground oil and gas reserves of theworld. Many countries with no underground natural gas could takeadvantage of this underwater resource. The environmental impacts of thissource would be similar to underground methane; however, there is morerisk of methane being released to the atmosphere due to the semi-stablenature of many methane hydrate formations. Methane is a powerfulgreenhouse gas—its effect on global warming is similar to 21 times asmuch carbon dioxide by weight over a 100-year period.

Industrial Waste Stream—Methane (Natural Gas) Source 24

Methane-rich waste streams are common in many industries, such as coalmining and the production of oil, chemicals, and steel. Capturing,separating, and compressing these methane sources for pipelinetransportation is not always economical compared to conventional naturalgas production from wells. In many cases, industrial processes vent orflare (burn) waste methane because it not economical to compress orliquefy the gas for transportation. In addition, remote sites likeoffshore oil production facilities may not even have the option ofpipeline transportation. Here again, natural gas hydrates may provide aneffective method for these stranded methane sources to be capturedwithout the equipment and energy expenses of methane compression orliquefaction, but NGH production technology is not fully developed atthis time.

Biogas—Methane (Natural Gas) Source 24

Similar to industrial waste streams of methane, various sources ofmethane-rich ‘biogas’ are common but not necessarily economical tocapture and transport when compared with fossil natural gas production.Global warming concerns and the carbon credit trading market created bythe Kyoto Protocol may justify more widespread utilization of thesesources. Some of the more easily captured biogas emissions come fromlandfills and wastewater treatment plants. Another potential source islarger livestock management facilities with liquid waste managementsystems, similar to domestic wastewater treatment systems.

Fuel Transportation System 32

Suitable fuel transportation systems 22 include pipelines, ships andtrucks. As with the hydrogen source 22 and the methane (natural gas)source 24, the transportation system 22 is selected and operated tominimize emissions and energy consumption.

Pipeline—Fuel Transportation System 32

For methane in the form of natural gas one suitable transportationmethod is through pipeline networks. Although moderately high-pressurepipelines are occasionally available, the majority of natural gasdispensing systems are supplied by low-pressure pipeline gas.

It is also possible to transport and distribute hydrogen throughpipelines. Many of the earliest gas pipeline networks were developed incities using ‘town gas’ for heating and lighting. This gas was a mixtureof hydrogen and carbon monoxide produced by steam reformation of coal.In addition, hydrogen pipelines are common in and between oil refineriesand chemical plants.

Liquefaction and Ship/Truck—Fuel Transportation System 32

For isolated island or coastal countries, imported liquefied natural gas(LNG) is sometimes the sole natural gas resource available. However, LNGmay be economically imported to countries with developed domesticnatural gas resources due to lower production costs overseas. Thenatural gas is liquefied in a refrigeration cycle that reduces thetemperature to about −160° C., thereby reducing the volume of themethane by a factor of about 600 at atmospheric pressure. This reductionin volume allows huge quantities to be shipped by special tankers overthe ocean, or by super-insulated tanks on rail cars or over-the-roadtrailers. On large industrial scales, the liquefaction process consumesroughly 15% of the natural gas energy.

Hydrogen may also be transported as a cryogenic liquid, but at the muchlower temperature of −253° C. at atmospheric pressure. The liquefactionprocess consumes approximately 30% of the fuel energy of the liquidhydrogen. Liquid transportation of hydrogen with tanks on rail cars oron-highway trailers is relatively common up to distances of about 1600km, but large-scale ocean shipping is not utilized for hydrogendistribution. Large consumers of hydrogen have dedicated productionfacilities, either on-site or through pipeline transportation.

It is also possible to transport a pre-blended, supercritical mixture ofLNG and hydrogen. The supercritical mixture has density similar to LNG,but it behaves more like a gas, remaining well mixed, in a single statewithout a liquid/gas interface surface, and completely filling the tankwithout splashing or sloshing.

Natural Gas Hydrate and Ship/Truck—Fuel Transportation System 32

The hydrated form of natural gas is not currently used fortransportation. However, NGH contains up to 13.4% methane by weight at adensity of about 0.9 g/ml. This implies a methane storage densityequivalent to 17 MPa of pressure, or about 2480 psi. To ensure long-termstability of the hydrate, an actual pressure of only about 2.5 MPa (360psi) and a storage temperature of −5° C. are all that is required.Metastability and relatively slow dissociation allows storage of NGH atatmospheric pressure and −5° C. temporarily—for days of transportationtime, for instance.

One transportation and distribution process pumps an NGH slurry topipeline pressures and heats to cause dissociation, similar to theprocess used for putting vaporized LNG into a pipeline. However, theliquid water left from the dissociated hydrate must then be separatedfrom the pressurized gas stream.

Compression and Truck—Fuel Transportation System 32

For short distances up to about 300 km over land, natural gas andhydrogen can be economically transported as a compressed gas by highwayand rail in DOT specification cylinders, highway cargo tanks and tubetrailers, and rail tank cars. Tube trailers may be an attractivesolution for distribution of hydrogen to HYTHANE refueling stationsserving smaller fleets. In addition, tube trailers or rail tanks maydistribute HYTHANE blended and compressed at a central facility tonearby refueling stations that do not have convenient natural gaspipeline availability.

Blending System 26

Referring to FIGS. 2-2D, further details of the blending system 26, andits' interface with the producing system 12 and the dispensing system 14are illustrated in schematic form. With respect to FIGS. 2-2D, FIG. 2illustrates the complete blending system 26, FIGS. 2A-2C, are enlargedportions of FIG. 2, and FIG. 2D contains the legend from FIGS. 2-2C.

The blending system 26 (FIG. 2) includes a methane (natural gas) conduit90 (FIG. 2A) and a hydrogen gas conduit 92 (FIG. 2A). A representativeflow rate for the methane (natural gas) conduit 90 (FIG. 2A) can beabout 400 SCFM at a minimum pressure of 50 psig. A representative flowrate for the hydrogen gas conduit 92 (FIG. 2A) can be about 100 SCFM ata minimum pressure of 50 psig. The size of the methane (natural gas)conduit 90 (FIG. 2A) can be selected as required with a 3 inch conduitbeing representative. The size of the hydrogen gas conduit 92 (FIG. 2A)can also be selected as required with a 1 inch conduit beingrepresentative.

The methane (natural gas) conduit 90 (FIG. 2A) is in flow communicationwith a ball valve 94 (FIG. 2A), a check valve 96 (FIG. 2A), a pressureregulator 98 (FIG. 2A) and a pressure relief valve 100 (FIG. 2A). Acabinet wall 180 can be located between the ball valve 94 (FIG. 2A) andthe check valve 96 (FIG. 2A). In addition, pressure gauges 102, 104(FIG. 2A) sense pressure on either side of the pressure regulator 98(FIG. 2A). The hydrogen gas conduit 92 (FIG. 2A) is in flowcommunication with a ball valve 106 (FIG. 2A), a check valve 108 (FIG.2A), a pressure regulator 110 (FIG. 2A) and a pressure relief valve 112(FIG. 2A). The cabinet wall 180 separates the ball valve 106 (FIG. 2A)and the check valve 108 (FIG. 2A). In addition, pressure gauges 116, 118(FIG. 2A) sense pressure on either side of the pressure regulator 110(FIG. 2A).

The methane (natural gas) conduit 90 (FIG. 2A) and the hydrogen gasconduit 92 (FIG. 2A) are also in flow communication with a parallel flowheat exchanger 120 (FIG. 2A) configured to cool the methane (naturalgas) and the hydrogen to a common temperature. A methane (natural gas)output conduit 122 (FIGS. 2A and 2B) of the parallel flow heat exchanger120 (FIG. 2A) includes an air operated valve 126 (FIG. 2B), atemperature gauge 128 (FIG. 2B), a pressure gauge 130 (FIG. 2B) and asonic nozzle 132 (FIG. 2B). A hydrogen gas output conduit 124 (FIGS. 2Aand 2B) of the parallel flow heat exchanger 120 (FIG. 2A) includes anair operated valve 134 (FIG. 2B), a temperature gauge 136 (FIG. 2B), apressure gauge 138 (FIG. 2B) and a sonic nozzle 140 (FIG. 2B). The airoperated valves 126, 134 (FIG. 2B) are in signal communication viacommunications lines 182 (FIG. 2B) with the master control system 44(FIG. 2A) and with a quality control system 176 (FIG. 2A) of the mastercontrol system 44 (FIG. 2A).

The methane (natural gas) output conduit 122 (FIG. 2B) and the hydrogengas output conduit 124 (FIG. 2B) of the parallel flow heat exchanger 120(FIG. 2A) are also in flow communication with a mixing chamber 144 (FIG.2B) wherein the methane (natural gas) and the hydrogen gas are mixed toform the hydrogen enriched fuel. The mixing chamber 144 (FIG. 2B)includes a pressure switch (low) 184 (FIG. 2B) and a pressure switch(high) 186 in signal communication via communications lines 182 with themaster control system 44 (FIG. 2A). The pressure switches 184, 186 (FIG.2B) can be used to control flow into and out of the mixing chamber 144(FIG. 2B). The mixing chamber 144 (FIG. 2B) is also in flowcommunication with a buffer tank 146 (FIG. 2B) wherein the hydrogenenriched fuel is collected and temporarily stored. The buffer tank 146(FIG. 2B) includes a pressure gauge 168 (FIG. 2B), a drain valve 148(FIG. 2B), a regulating valve 150 (FIG. 2B), and a pressure relief valve152 (FIG. 2B) configured to vent to a safe location such as a ventstack.

An output conduit 154 (FIGS. 2B and 2C) of the buffer tank 146 (FIG. 2B)includes a ball valve 156 (FIG. 2C), a pressure gauge 158 (FIG. 2C) anda check valve 160 (FIG. 2C) in flow communication with the compressorsystem 28 (FIG. 2C). The compressor system 28 (FIG. 2C) is configured topressurize the hydrogen enriched fuel to a selected pressure. Thecompressor system 28 (FIG. 2C) in turn is in flow communication with thestorage system 30 (FIG. 2C), which is configured to store a selectedquantity of the hydrogen enriched fuel at the selected pressure. Thestorage system 30 (FIG. 2C) is also in flow communication with thedispensing system 14 (FIG. 2C). In addition, a HYTHANE recycle loop 162(FIG. 2C) is in flow communication with the storage system 30 (FIG. 2C)and with the output conduit 154 (FIG. 2C) from the buffer tank 146 (FIG.2B). The HYTHANE recycle loop 162 (FIG. 2C) includes a pressureregulator 164 (FIG. 2C) and a ball valve 166 (FIG. 2C).

Communication lines 182 (FIG. 2C) establish signal communication betweenthe master control system 44 (FIG. 2A), the compressor system 28 (FIG.2C), the storage system 30 (FIG. 2C), the engine control module 46 (FIG.2C) on the vehicle 16 (FIG. 2C), and the audit and control module 88(FIG. 2C) of the dispensing system 14 (FIG. 2C). In addition, thequality control segment 176 (FIG. 2C) of the master control system 44(FIG. 2A) includes a quality specimen loop 170 (FIG. 2B) in flowcommunication with the buffer tank 146 (FIG. 2B) configured to extractand analyze quality control samples. The quality specimen loop 170 (FIG.2B) also includes a pressure regulator 174 (FIG. 2B) and a regulatingvalve 172 (FIG. 2B). The master control system 44 (FIG. 2A) alsoincludes a safety system 178 (FIG. 2A) configured to use pressure,temperature and flow data to insure safety.

The master control system 44 (FIG. 2A) includes computers or controllersprogrammed with software configured to achieve control of the system 10including the producing system 12 and the dispensing system 14. Inaddition, the master control system 44 (FIG. 2A) operating inconjunction with the safety system 178 (FIG. 2A) provides a safetyoverride system. In addition, the master control system 44 (FIG. 2A)provides quality assurance monitoring and control during blending anddispensing of the hydrogen enriched fuel. Further, the master controlsystem 44 (FIG. 2A) has the capability to use any of the various formsof HYTHANE, although some of the components can be tailored to meet thespecific needs of each type of fuel. The master control system 44 (FIG.2A) also collects data, verifies parameters and performs real timecomputing of user configurable output parameters. In addition, themaster control system 44 (FIG. 2A) performs certified auditing fordifferent tradable emissions programs including carbon or NOx creditsunder the Kyoto Protocol.

Referring to FIG. 3, operational characteristics of the master controlsystem 44 are illustrated in a flow diagram. As indicated by bubble 200,the blending system 26 is controlled to provide the constituents (e.g.,hydrogen gas and methane) in an integrated, proportional mixture at aselected pressure and temperature. As indicated by bubble 202, dynamiccontrol of the blending system 26 and control of the safety system 178are provided. As indicated by bubble 204, the dispensing system 14 anddelivery to the vehicle 16 are controlled. As indicated by bubble 208,the HYTHANE quality control system 176, and the communication system 188to vehicle interface are controlled. As indicated by bubble 206, thevehicle engine control module 46 including HYTHANE recognition, datacollection, audit and safety are controlled. Further details of the datacollection and auditing functions of the master control system 44 willnow be described.

Master Control System 44—Exhaust Emissions Data Collection and Audit

The 1997 Kyoto Protocol created market-based emissions tradingmechanisms to help countries reduce the cost of meeting their greenhousegas emissions reduction targets. In order to take advantage of theemissions credits generated by the use of HYTHANE, a properly validatedand verified system is necessary to account for any reduction in carbondioxide or equivalent greenhouse gas emissions. For local air qualitycontrol (not as part of the Kyoto Protocol), some areas also tradecredits for reductions in NOx and SOx (oxides of sulfur) emissions.

Data Recorded at Dispensing System 14

The simplest way to track carbon dioxide emissions is to track overallfuel consumption of the vehicle fleet at the dispensing system 14. Inthis case, the dispensing system 14 can include the audit and controlmodule 88 (FIG. 1) in signal communication with the engine controlmodule 46 (FIG. 1) on the vehicle 16 (FIG. 1). If the composition of thefuel is known, then it is a straightforward calculation to determine thekilograms of carbon dioxide exhausted to the atmosphere for everykilogram of HYTHANE dispensed and ultimately combusted. However, as willbe discussed in the Data Calculation and Reporting section, this methodwill only account for the actual carbon dioxide emissions, not any otherpossible greenhouse gas emissions or life cycle benefits.

Data Collected by On-Board Equipment

Access to on-board data enables tracking of not just fuel consumption,but fuel consumption at specific environmental and engine operatingconditions. With well-characterized engine emissions behaviorinformation, it is then possible to quantify all the engine emissions,not just carbon dioxide.

There is a spectrum of levels to which the data collection anddistribution functions may be performed by the master control system 44(FIG. 1) and the engine control module 46 (FIG. 1).

-   -   1. Sensor data can be collected, stored, and distributed to the        master control system 44 (FIG. 1) by stand-alone on-board        equipment.    -   2. Sensor data can be collected by the engine control module 46        (FIG. 1) and sent as a real-time data stream (through a typical        SAE J1939 CAN bus, for instance) to the master control system 44        (FIG. 1).    -   3. Sensor data can be collected and stored by the engine control        module 46 (FIG. 1) and occasionally sent to a stand-alone        distribution unit to be broadcast to the master control system        44 (FIG. 1).    -   4. All of the data collection, storage, and communication        functions are integrated into the engine control module 46 (FIG.        1).

The data stored on-board by the engine control module 46 (FIG. 1) may betransmitted by wire connection or wireless communication (e.g.,communication system 188—FIG. 4) to the master control system 44 (FIG.1). This data transmission process may occur during refueling at thedispensing system 14 (FIG. 1), or data may be collected directly by thevehicle fleet agency. For example, the engine control module 46 can bein signal communication via wireless communication with the audit andcontrol module 88 (FIG. 1) on the dispensing system 14.

Data Calculation and Reporting

Simple carbon dioxide emissions reduction can be calculated from totalfleet fuel consumption and fuel composition data. This method does nottake advantage of additional equivalent greenhouse gases, like methaneemissions, or potential life cycle benefits. This may leave asignificant number of emissions reduction credits unaccounted for, sinceother gases, like methane, have a much stronger greenhouse effect.

The next level of data calculation and reporting adds histogrammaticinformation about the fuel consumption at various engine operatingconditions; this data must be collected on-board the vehicles 16(FIG. 1) in the fleet. This information can be used to calculate thetotal emissions of any of the exhaust constituents for each individualvehicle 16. Calculated data from all of the vehicles 16 in the fleet arethen aggregated for reporting of carbon dioxide equivalent reductions.In addition, other gases may qualify for regional air quality emissionstrading credits, like NOx and SOx.

Information about the fuel sources, refueling stations 34 (FIG. 1), andbaseline vehicle fleet provides the final level of data needed forcomplete life cycle assessment of emissions reduction of the system 10(FIG. 1). For instance, one station may receive natural gas from apipeline (which could be a mixture of well gas and LNG transported byship), while another station may use only LNG transported by ship andtruck. The hydrogen sources are likely to be even more varied. In somecases, the baseline may be a fleet of natural gas buses converted toHYTHANE, while in other cases, an entire baseline fleet of diesel busesmay be completely replaced by new HYTHANE units. The greenhouse gasemissions calculated over the entire life cycle is dependent on the pathtaken from “wells to wheels,” and it is this total life cycle assessmentwhich must be compared to the baseline as a valid method for reportingthe total HYTHANE greenhouse gas emissions reduction.

Storage System 30

The pre-blended HYTHANE can be stored in the storage system 30 (FIG. 2C)for days at a time without venting, as long as the storage conditionsmaintain a supercritical state of the methane in the hydrogen gas. Thedownside to supercritical storage is that the tanks must be designed forboth pressure and insulation (but not as much pressure as compressed gasstorage and not as much insulation as cryogenic liquid storage).

Separate Storage

As another alternative to storing the blended HYTHANE in the storagesystem 30 (FIG. 2C) in a supercritical state, the hydrogen and methanecan each be stored independently, as high pressure compressed gases orcryogenic liquids. One advantage of this approach is that the separatefuel source transportation tanks can also be used as refueling stationstorage containers until depleted. For example, hydrogen tube trailerscan be parked at the refueling station, used up, and trucked back to thecentral distribution hub for another cycle.

When the refueling station 34 (FIG. 2C) is located relatively remotelyfrom natural gas pipelines, LNG storage offers economical benefits, notjust for transportation, but also for the production of LCNG, which isCNG (compressed natural gas) produced from pumped and vaporized LNG.LCNG can be produced from LNG on-the-fly during vehicle refueling, so nohigh pressure natural gas storage is required, only a small buffer tank.Separate storage of natural gas and hydrogen also allows separatedispensing of fuels, such that LNG, CNG, hydrogen, and HYTHANE vehiclescould be refilled at one location. However, if only compressed hydrogenand CNG or LCNG is stored separately, then high pressure HYTHANEblending is necessary during compressed gas vehicle tank refueling,which may not be as simple and consistent as low pressure,pre-compressor HYTHANE blending.

Vehicle Storage

Like storage at the refueling station 34 (FIG. 2C), there are manyoptions for HYTHANE storage in vehicles. One suitable method of vehiclestorage configures the vehicle fuel tank 42 as a cryogenic vessel ordewar configured to store the pre-blended HYTHANE in a supercriticalstate. However, the method of storage at the refueling station 34 (FIG.2C) combined with the method of storage in the vehicle 16 (FIG. 2C)places constraints on the methods available for dispensing blendedHYTHANE to high pressure vehicle fuel tanks 42 (FIG. 2C).

Using HYTHANE, about 20% of the volume of the vehicle fuel tank 42contains hydrogen, which has lower energy content per unit volume thanmethane. In addition, methane has favorable compressibilitycharacteristics at higher pressures, whereas hydrogen's compressibilityworsens as the pressure increases. The overall effect is that the rangeof a natural gas vehicle may be reduced by as much as 20% when it isconverted to HYTHANE. This effect can be mitigated somewhat by thecomposition of the natural gas and its higher hydrocarbon content. Withethane, propane, and butane all saturated (non-condensing) in a tank ofHYTHANE at 25 MPa (3600 psi) and 0° C., the volumetric energy density ofthe mixture is within 5% of a pure methane tank at the same conditions.In some situations in which range is a critical issue, intentionally‘spiking’ the HYTHANE with higher hydrocarbons may be desirable.

As an alternative to the blending system 26 (FIG. 2) hydrogen gas and asupercritical methane fuel can mixed and compressed using a vortexmixer, as described in U.S. application Ser. No. 11/273,397, filed onNov. 14, 2005, entitled “Method And System For Producing A SupercriticalCryogenic Fuel (SCCF)”, which is incorporated herein by reference.

Dispensing System 14

Referring to FIG. 4, the dispensing system 14 is shown separately. Thedispensing system 14 includes a hose 36 and a fill valve 38 adapted forsealed gas/fluid communication with the vehicle fuel tank 42 (FIG. 1) onthe vehicle 16 (FIG. 1). The dispensing system 14 (FIG. 4) also includesvarious internal components 40 including metering, control, andswitching components in combination with supporting solenoid valves,pressure gauges and safety related components. In addition, thecomponents 40 can be configured for the specific HYTHANE fuel type to bedispensed. For high pressure gaseous HYTHANE, the set up of thecomponents 40 can be similar to conventional CNG dispensers used in theexisting natural gas vehicle market.

The dispensing system 14 can also include the previously described auditand control module 88 (FIG. 4). In addition to being in signalcommunication with the previously described communications lines 182(FIG. 2C), the audit and control module 88 can be in signalcommunication with the signal communications system 188. The signalcommunications system 188 can comprise a wireless system, such as a RF(radio frequency) system, configured to transmit signals between thedispensing system 14 and other components of the system 10 (FIG. 1). Forexample, the communications system 188 can establish signalcommunication with the engine control module 46 (FIG. 1), and with themaster control system 44 (FIG. 2A). Rather than a wireless system, thecommunications system 188 can comprise a hardwired connection or a cardreader system.

Dispensing Separate CNG and Compressed Hydrogen to Mix in High PressureTanks

As mentioned in the storage section, the natural gas may be stored aslow pressure LNG and only pumped to high pressure and vaporized duringvehicle refueling. Another possibility is that compressed natural gasand compressed hydrogen are stored separately to preserve theflexibility to refuel CNG, hydrogen, or HYTHANE vehicles at onefacility. In these cases, HYTHANE may have to be dispensed inalternating squirts, or aliquots, of compressed hydrogen and CNG to mixin the vehicle tanks. This complicates the dispensing of HYTHANE and maynot provide mixtures as consistent as other HYTHANE blending methods.

Dispensing Separate Cryogenic Liquids or a Supercritical HYTHANE Mixture

Space-constrained or long-range vehicles may require the higher densityof cryogenic fuel storage. Separate LNG and liquid hydrogen tanks couldbe used, but vehicle refueling then requires separate fuel connectionsand the HYTHANE blending must be done on-board the vehicle.Alternatively, a supercritical cryogenic HYTHANE blend can be pumpedthrough one fuel connection and stored in one vehicle tank.

Dispensing Cryogenic Liquids or Compressed Gases to Separate VehicleTanks

In some unusual circumstances, it may be desirable to use a variableHYTHANE composition, or use either natural gas or hydrogen fuelexclusively during certain engine conditions, or at particular locationsalong the vehicle route. In these situations, it may be necessary todispense and store the natural gas and hydrogen separately in thevehicle, either in cryogenic tanks, high-pressure gas tanks, or acombination.

Vehicle Delivery System 20

Once the fuel is on-board the vehicle 16 (FIG. 1), there are severaloptions for the delivery of HYTHANE to the vehicle engine 18 (FIG. 1).There are also a variety of options for the way in which the HYTHANE isultimately combusted within the vehicle engine 18 (FIG. 1).

Pre-Blended Delivery

In most cases, the HYTHANE can be stored as a pre-blended, compressedgas. Filters, electric solenoid lock-off valves, and pressure regulatorsand their associated plumbing connect the fuel tank 42 (FIG. 1) ortanks, with the fuel delivery system 20 (FIG. 1) and the engine controlmodule 46 (FIG. 1) to deliver HYTHANE to the engine 18 (FIG. 1).

If HYTHANE is stored as a pre-mixed supercritical fuel, the tankpressures will be high enough to use the same delivery system 20(FIG. 1) as the pre-mixed compressed gas example above. However, thesupercritical HYTHANE mixture must be heated and vaporized as it leavesthe vehicle fuel tank 42 (FIG. 1).

Likewise, if one of the HYTHANE fuel components is stored separately asa cryogenic liquid, the fuel must be heated and vaporized as it isremoved from the fuel tank 42 (FIG. 1). In this case, however, pressurereduction regulators may not be necessary because the liquid tank is notusually kept at high pressures. Only filters, lock-off valves, andplumbing connect the tank and the engine fuel system.

Fuels Stored Separately, HYTHANE Blended On-Board

When the hydrogen and natural gas are stored in the vehicle 16 (FIG. 1)separately, the HYTHANE must then be blended on-board. In order toachieve consistent HYTHANE blending ratios over the wide fuel flow rangeof the engine 18, special blending or delivery equipment is necessary.

One blending method is explained in U.S. Pat. No. 4,520,763 which isincorporated herein by reference. This blending method uses thecompressibility of gases to achieve proportional flow between the airentering the engine 18 (FIG. 1) and the amount of fuel that is injectedinto it. Hydrogen Components, Inc. of Littleton, Colo., has used thistechnique, called “Constant Volume Injection” (CVI), for 25 years forcontrolling hydrogen engines. The same technique can be used formetering two or more gases in a precise, fixed proportion.

Referring to FIG. 5, a CVI unit 50 is illustrated. The CVI unit 50includes the following components.

-   -   52 exhaust port    -   54 valve seal    -   56 valve guide    -   58 shim    -   60 roller guide    -   62 lube oil    -   64 valve seat    -   66 intake port    -   68 intake manifold    -   70 vent passage    -   72 spring seat    -   74 spring    -   76 spring retainer    -   78 keepers    -   80 roller tappet    -   82 cam    -   84 exhaust valve    -   86 CVI chamber

The cam 82, synchronized with the engine's camshaft, operates the CVIunit 50 in a 3-step sequence:

-   -   1. An intake valve (not shown) opens, allowing the hydrogen and        methane fuels to fill their respective CVI chamber 86. There is        a CVI chamber 86 for each gaseous fuel, one for hydrogen and one        for methane (CNG).    -   2. A precisely measured quantity of hydrogen fuel is trapped in        a CVI chamber 86 by closing the intake valve (not shown).        Likewise, a corresponding quantity of methane fuel is trapped in        it's respective CVI chamber 86.    -   3. The exhaust valve 84 opens and discharges the hydrogen and        methane fuel gases into a fuel buffer volume (not shown) for        mixing and delivery to the engine fuel control system 48.

The basic principle of operation is that a sealed chamber of preciselyknown volume at a controlled pressure and a fixed temperature holds aknown amount of gas. The amount of gaseous fuel delivered by the CVIchamber 86 is proportional to engine RPM, the chamber volume, and thepressure difference between the inlet valve (not shown) and the exhaustvalve 84. The objective of blending 7% hydrogen by energy contentrequires about 20% hydrogen by volume in natural gas. In ideal gastheory, the volume of a chamber 86 used for natural gas should be 4times larger than the volume of a chamber 86 used for hydrogen to yieldan 80/20% mix. Test results have shown that the theoretical chambervolumes need to be modified slightly for real gas behavior. As long asthe natural gas and hydrogen are supplied to the CVI unit 50 at the samepressure, and the two chambers 86 discharge to the same buffer volume,the fuel mixture composition will be maintained at a constant ratio. Itis also possible to use a sensor to verify the final fuel mixturecomposition in this buffer volume.

Fuels Stored Separately and Delivered to Engine Separately with ParallelFuel Systems

Parallel fuel control systems may also be used for delivering hydrogenand natural gas to an engine in a precise, known ratio. If the open-loopfuel delivery characteristics are known for the fuel metering componentsover the whole operating range, such as well-characterized fuelinjectors, then the natural gas and hydrogen can be metered separatelyto finally mix at the engine intake or within the engine cylinder.Although two separate sets of fuel metering components are used, theymay both be driven by one engine control module.

In most cases, a constant HYTHANE composition is used, and the enginecalibration is optimized for this specific mixture. However, in somecircumstances, it may be advantageous to be able to operate on eitherHYTHANE or natural gas only, depending on fuel availability. Withon-board HYTHANE blending, the hydrogen fuel delivery system can be shutoff, and a fuel control system 48 (FIG. 5) can use dual calibrationtables to accommodate either NG-only or HYTHANE fuel supplies. To takethe fuel system flexibility one step further, it is also possible forthe fuel control system 48 (FIG. 5) to sense the incoming fuel hydrogencontent and compensate for variable HYTHANE composition. With separatehydrogen and natural gas vehicle storage, it is even possible toactively control the fuel mixture and provide natural gas only, hydrogenonly, or any mixture in between for different engine operatingconditions or vehicle route locations.

HYTHANE Engine Operation

There are basically two modes of engine operation used for vehicleengine operation, lean burn and stoichiometric. Depending on thepriorities and emissions goals, HYTHANE may be used with either enginetype to improve combustion stability, increase power and efficiency, andreduce harmful exhaust emissions.

Operating an engine at lean air/fuel ratios generally improvesefficiency. However, the power is reduced, so a turbocharger is usuallyadded to increase airflow and power. By providing higher intake pressureand utilization of waste exhaust gas energy, the turbo also furtherimproves efficiency. Maximum efficiency is constrained by flammabilityas the air/fuel ratio goes leaner and by knock as the intake pressure isincreased. NOx emissions reduction is also limited by the leanflammability limit, where unburned hydrocarbon (methane) emissionsdramatically increase. The addition of hydrogen to a natural gas engineoperating close to the lean flammability limit, with no othercalibration changes, will increase NOx, increase power, increaseefficiency, and reduce unburned hydrocarbons. However, the hydrogen alsoimproves the fuel flammability and allows leaner operation and reducedignition timing. These calibration parameters can be optimized forhigher efficiency, higher power, or reduced NOx emissions without anincrease in unburned hydrocarbons. The most economical way to reducehydrocarbon emissions dramatically is with the use of an oxidationcatalyst, however the stable methane molecules require relatively highexhaust temperatures for effective catalysis. Many research anddemonstration projects have determined that a hydrogen content of 7% byenergy in HYTHANE is optimum for the reduction of NOx (by about 50% vs.NG), without any penalty in efficiency, power, or hydrocarbon emissions.More hydrogen will allow leaner operation, but lower NOx is not possiblewithout a sacrifice in efficiency, power, or hydrocarbon emissions (dueto lower exhaust temperatures in the oxidation catalyst at leanerconditions).

Stoichiometric Combustion

A chemically balanced air/fuel mixture is referred to as a‘stoichiometric’ air/fuel ratio. Natural gas engines operating at thiscondition provide maximum power, but efficiency and engine-out emissionsare worse than lean burn operation. In addition, exhaust temperaturesare at a maximum during stoichiometric combustion at full load, and manyheavy-duty diesel-derivative engines are not designed for these hightemperatures and heat loads.

Despite these apparent shortcomings, most light-duty gasoline enginesare stoichiometric, and many heavy-duty engines are currently beingdeveloped for this type of operation. The key enabling technology forstoichiometric engines is the three-way exhaust catalyst. This devicereduces NOx emissions and uses its oxygen, along with oxygen left overfrom incomplete combustion in the engine, to also oxidize carbonmonoxide (CO) and unburned hydrocarbons (HC). The overall level ofpost-catalyst emissions can be an order of magnitude lower than evenlean-burn combustion with natural gas. Although the emissions levels arealready very low for stoichiometric, catalyzed natural gas engines,HYTHANE can still improve the emissions significantly. Hydrogenstimulates the combustion of methane and is a powerful reducing agentfor NOx and unreacted oxygen. As little as 5% hydrogen by energy hasbeen demonstrated to reduce NOx and CO by more than 50% and totalhydrocarbon emissions by 35% in a stoichiometric CNG light-duty vehiclewith three-way catalysis.

Lower efficiency and high temperatures are the undesirablecharacteristics of stoichiometric combustion to be improved forheavy-duty engines. Both of these issues can be mitigated with the useof exhaust gas recirculation (EGR). Like lean-burn operation, EGRincreases efficiency but sacrifices power; so again, turbocharging isfrequently used to improve the engine's power density. For the mostpart, lean-burn engines reduce exhaust temperatures and NOx by reducingcombustion temperatures by diluting the air/fuel charge with excess air.EGR accomplishes the same effect but reduces NOx even further becausethe recycled exhaust has little or no oxygen. In any case, anyengine-out NOx is almost completely eliminated in the catalyst when astoichiometric air/fuel ratio is used. Like lean-burn engines,stoichiometric EGR engines benefit from the addition of hydrogen becauseadditional EGR can be used before the dilution flammability limit of themixture causes misfire. This increases efficiency and lowers exhausttemperatures and engine-out NOx emissions. In addition, the use of EGRstill allows the benefits of hydrogen with stoichiometric three-waycatalysis to be realized, such as combustion stimulation and highcatalytic reactivity at relatively low temperatures. For heavy-dutyapplications, stoichiometric turbocharged engines using EGR andthree-way catalysts provide the lowest possible emissions with HYTHANEfuel, but at higher cost than lean-burn operation due to the expense andcomplexity of the EGR system and slightly lower efficiency.

HYTHANE bus fuel is a blend of 7% hydrogen by energy content in naturalgas (20% H₂ by volume). FIG. 6 shows the effect of various hydrogenconcentrations on NOx emissions from a modified Cummins L-10 bus enginein a steady state simulation of the Federal emissions test.

Thus the invention provides an improved system and method for producing,dispensing, using and monitoring the life cycle emissions of a hydrogenenriched fuel. While the invention has been described with reference tocertain preferred embodiments, as will be apparent to those skilled inthe art, certain changes and modifications can be made without departingfrom the scope of the invention as defined by the following claims.

1. A system comprising: a producing system configured to produce ahydrogen enriched fuel by blending hydrogen from a hydrogen source andhydrocarbon from a hydrocarbon source; source data comprisinginformation on the hydrogen source and on the hydrocarbon source and ontransportation of the hydrogen and the hydrocarbon from the hydrogensource and the hydrocarbon source to the producing system; a vehicleconfigured to use the hydrogen enriched fuel; and a control system insignal communication with the producing system and the vehicle, thecontrol system configured to control production of the hydrogen enrichedfuel by the producing system, to sense, retrieve and store emissiondata, fuel consumption data and mileage data during use of the hydrogenenriched fuel by the vehicle, the control system configured to quantifyemissions and air quality trading credits using the source data, theemission data, the fuel consumption data and the mileage data.
 2. Thesystem of claim 1 further comprising a plurality of vehicles configuredto use the hydrogen enriched fuel, and wherein the control system isconfigured to sense, retrieve and store the emission data, the fuelconsumption data and the mileage data during use of the hydrogenenriched fuel by each of the vehicles, and to aggregate the emissionsand the air quality trading credits for all of the vehicles.
 3. Thesystem of claim 1 further comprising a dispensing system in signalcommunication with the control system configured to dispense thehydrogen enriched fuel into the vehicle and wherein the control systemis configured to sense the emissions produced by the dispensing system.4. The system of claim 1 wherein the control system includes baselinevehicle fleet information and is adapted to compare the emission data,the fuel consumption data and the mileage data for the vehicle to thebaseline vehicle fleet information.
 5. A system comprising: a producingsystem configured to produce a hydrogen enriched fuel by blendinghydrogen from a hydrogen source and hydrocarbon from a hydrocarbonsource; source data comprising information on the hydrogen source and onthe hydrocarbon source and on transportation of the hydrogen and thehydrocarbon from the hydrogen source and the hydrocarbon source to theproducing system; a plurality of vehicles, each vehicle comprising afirst control module and an engine configured to use the hydrogenenriched fuel; a dispensing system configured to dispense the hydrogenenriched fuel into the vehicles, the dispensing system comprising asecond control module in signal communication with the first controlmodule; and a control system in signal communication with the firstcontrol module and the second control module configured to sense,retrieve and store emission data, fuel consumption data and mileage dataduring use of the hydrogen enriched fuel by the vehicles and to quantifyemissions and to compare the emission data, the fuel consumption dataand the mileage data to baseline vehicle information, the control systemconfigured to calculate air quality trading credits using the emissiondata, the baseline vehicle information and the source data.
 6. Thesystem of claim 5 wherein the hydrogen source and the hydrocarbon sourceare selected to minimize emissions and energy consumption duringproduction of the hydrogen and the hydrocarbon.
 7. The system of claim 5wherein the plurality of vehicles comprises a fleet of buses.
 8. Thesystem of claim 5 wherein the control system is configured to calculatethe air quality trading credits during dispensing of the hydrogenenriched fuel by the dispensing system, and the use of the hydrogenenriched fuel by the vehicles.
 9. The system of claim 5 wherein signalcommunication between the first control module and the second controlmodule comprises wireless communication.
 10. The system of claim 5wherein signal communication between the first control module and thesecond control module comprises a card reader or a hardwired connection.11. A system comprising: a producing system configured to produce ahydrogen enriched fuel by blending hydrogen from a hydrogen source andhydrocarbon from a hydrocarbon source; source data comprisinginformation on the hydrogen source and on the hydrocarbon source and ontransportation of the hydrogen and the hydrocarbon from the hydrogensource and the hydrocarbon source to the producing system; a vehiclehaving an engine configured to use the hydrogen enriched fuel; adispensing system configured to dispense the hydrogen enriched fuel intothe vehicle; and a control system in signal communication with theproducing system, the vehicle and the dispensing system, the controlsystem configured to control the producing system, the control systemconfigured to sense, retrieve and store emission data from the producingsystem, the dispensing system, and the vehicle, and to calculate airquality trading credits using the emission data and the source data. 12.The system of claim 11 wherein the hydrogen source and the hydrocarbonsource are selected and operated to reduce emissions relative to a baseline fuel.
 13. The system of claim 11 wherein the hydrogen source isselected from the group consisting of electrolysis, exotic watersplitting, industrial waste streams, wells, reforming and gasification.14. The system of claim 11 wherein the hydrocarbon source is selectedfrom the group consisting of wells, industrial waste streams, andbiogas.
 15. The system of claim 11 wherein the hydrocarbon comprisesmethane.
 16. The system of claim 11 wherein the producing systemincludes a blending system in signal communication with the controlsystem configured to blend the hydrogen and the hydrocarbon into thehydrogen enriched fuel.
 17. The system of claim 11 wherein the controlsystem includes an engine control module on the vehicle configured toprovide emission and energy consumption data by the vehicle during useof the hydrogen enriched fuel, and a control and audit module on thedispensing system in signal communication with the engine control moduleconfigured to receive the data.
 18. A system comprising: a producingsystem comprising a blender configured to blend a hydrogen gas from ahydrogen source and a hydrocarbon fuel from a hydrocarbon source into ahydrogen enriched fuel; source data comprising information on thehydrogen source and on the hydrocarbon source and on transportation ofthe hydrogen gas and the hydrocarbon fuel from the hydrogen source andthe hydrocarbon source to the producing system; a vehicle having anengine configured to use the hydrogen enriched fuel, and a first controlmodule configured to sense operating conditions and calculate emissionsfrom the engine; and a control system including a second control modulein signal communication with the first control module configured tocontrol the blender, to sense, retrieve and store emission data, fuelconsumption data and mileage data during the use of the hydrogenenriched fuel by the vehicle, and to quantify emissions and air qualitytrading credits using the source data and the emission data.
 19. Thesystem of claim 18 further comprising a dispensing system configured todispense the hydrogen enriched fuel into the vehicle, and wherein thesecond control module is located on the dispensing system.
 20. Thesystem of claim 19 wherein signal communication between the firstcontrol module and the second control module comprises wirelesscommunication, a card reader or a hard wired connection.
 21. The systemof claim 20 further comprising a storage system in flow communicationwith the dispensing system configured to store the hydrogen enrichedfuel.
 22. The system of claim 21 wherein the hydrocarbon comprisesmethane in a supercritical state.
 23. A system comprising: a producingsystem configured to produce a hydrogen enriched fuel by blendinghydrogen from a hydrogen source and hydrocarbon from a hydrocarbonsource; source data comprising information on the hydrogen source and onthe hydrocarbon source and on transportation of the hydrogen and thehydrocarbon from the hydrogen source and the hydrocarbon source to theproducing system; a dispensing system configured to dispense thehydrogen enriched fuel; a vehicle comprising an engine, a fuel deliverysystem on the vehicle in fluid communication with the dispensing systemconfigured to deliver the hydrogen enriched fuel to the engine, and anengine control module configured to calculate emissions from the engineduring combustion of the hydrogen enriched fuel; and a control systemhaving an audit and control module on the dispensing system in signalcommunication with the engine control module configured to controldispensing of the hydrogen enriched fuel by the dispensing system, tostore emission data during use of the hydrogen enriched fuel by thevehicle, and to calculate air quality trading credits using the emissiondata and the source data.
 24. The system of claim 23 wherein thehydrocarbon comprises natural gas.
 25. The system of claim 23 furthercomprising a wireless communication system for providing signalcommunication between the audit and control module and the enginecontrol module.
 26. A method for producing, dispensing, using andmonitoring a hydrogen enriched fuel comprising: providing a hydrogen gasfrom a hydrogen source and a hydrocarbon fuel from a hydrocarbon source;providing source data comprising information on the hydrogen source andon the hydrocarbon source and on transportation of the hydrogen gas andthe hydrocarbon fuel from the hydrogen source and the hydrocarbonsource; blending the hydrogen gas and the hydrocarbon fuel into thehydrogen enriched fuel; dispensing the hydrogen enriched fuel into avehicle having an engine configured to use the hydrogen enriched fuel;using the hydrogen enriched fuel in the vehicle engine; sensing,retrieving and storing emission data, fuel consumption data and mileagedata during the using step; and quantifying emissions and air qualitytrading credits using the source data, the emission data, the fuelconsumption data and the mileage data.
 27. The method of claim 26further comprising quantifying the emissions and the air quality tradingcredits produced during the blending step, the dispensing step and theusing step.
 28. The method of claim 26 wherein the quantifying stepquantifies the emissions over a life cycle of the hydrogen enrichedfuel.
 29. The method of claim 26 wherein the quantifying step quantifiesthe air quality trading credits over a life cycle of the hydrogenenriched fuel.
 30. The method of claim 26 further comprising performingthe dispensing step, the using step, the sensing step and quantifyingstep on a fleet of vehicles having baseline vehicle fleet information,and using the data and the information to reduce the emissions and thefuel consumption of the vehicle.
 31. A method for producing, using andmonitoring a hydrogen enriched fuel comprising: providing a producingsystem configured to produce the hydrogen enriched fuel from hydrogenfrom a hydrogen source and a hydrocarbon fuel from a hydrocarbon source;providing source data comprising information on the hydrogen source andon the hydrocarbon source and on transportation of the hydrogen gas andthe hydrocarbon fuel from the hydrogen source and the hydrocarbonsource; producing the hydrogen enriched fuel using the producing system;providing a vehicle configured to use the hydrogen enriched fuel;providing a control system in signal communication with the producingsystem and the vehicle, the control system configured to store thesource data, to control production of the hydrogen enriched fuel, tomonitor emissions produced by the producing system, and to monitoremissions produced by the vehicle during use of the hydrogen enrichedfuel at specific environmental and engine operating conditions; usingthe hydrogen enriched fuel in the vehicle; and monitoring emissionsduring the producing step and the using step using the control system toestimate and track the emissions over a life cycle of the hydrogenenriched fuel.
 32. The method of claim 31 wherein the control system isconfigured to monitor a quality of the hydrogen enriched fuel and tomonitor safety during production of the hydrogen enriched fuel.
 33. Themethod of claim 31 further comprising providing a dispensing system insignal communication with the control system configured to dispense thehydrogen enriched fuel into the vehicle, dispensing the hydrogenenriched fuel into the vehicle using the dispensing system, andmonitoring the emissions during the dispensing step using the controlsystem.
 34. The method of claim 31 further comprising auditing tradableemission credits using the control system.